EP1248082A1 - Accéléromètre à fibres optiques pour mesurer un débit de fluide - Google Patents

Accéléromètre à fibres optiques pour mesurer un débit de fluide Download PDF

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Publication number
EP1248082A1
EP1248082A1 EP20020006630 EP02006630A EP1248082A1 EP 1248082 A1 EP1248082 A1 EP 1248082A1 EP 20020006630 EP20020006630 EP 20020006630 EP 02006630 A EP02006630 A EP 02006630A EP 1248082 A1 EP1248082 A1 EP 1248082A1
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Prior art keywords
fluid flow
sensing
sensor
fibre optic
sensors
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EP20020006630
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German (de)
English (en)
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EP1248082B1 (fr
Inventor
John Michael Beresford
Christopher John Collister
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Thales Underwater Systems Ltd
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Thales Underwater Systems Ltd
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Priority claimed from GB0108739A external-priority patent/GB0108739D0/en
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    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01P—MEASURING LINEAR OR ANGULAR SPEED, ACCELERATION, DECELERATION, OR SHOCK; INDICATING PRESENCE, ABSENCE, OR DIRECTION, OF MOVEMENT
    • G01P15/00—Measuring acceleration; Measuring deceleration; Measuring shock, i.e. sudden change of acceleration
    • G01P15/02—Measuring acceleration; Measuring deceleration; Measuring shock, i.e. sudden change of acceleration by making use of inertia forces using solid seismic masses
    • G01P15/08—Measuring acceleration; Measuring deceleration; Measuring shock, i.e. sudden change of acceleration by making use of inertia forces using solid seismic masses with conversion into electric or magnetic values
    • G01P15/093—Measuring acceleration; Measuring deceleration; Measuring shock, i.e. sudden change of acceleration by making use of inertia forces using solid seismic masses with conversion into electric or magnetic values by photoelectric pick-up
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01F—MEASURING VOLUME, VOLUME FLOW, MASS FLOW OR LIQUID LEVEL; METERING BY VOLUME
    • G01F1/00—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow
    • G01F1/66—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow by measuring frequency, phase shift or propagation time of electromagnetic or other waves, e.g. using ultrasonic flowmeters
    • G01F1/666—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow by measuring frequency, phase shift or propagation time of electromagnetic or other waves, e.g. using ultrasonic flowmeters by detecting noise and sounds generated by the flowing fluid

Definitions

  • the present invention relates to an apparatus and a method of sensing fluid flow. More particularly though not exclusively, the present invention relates to a fluid flow sensing system employing a sensor device together with remote processing means to provide the user with measurements of fluid flows in production tubing, pipelines, open wells, tunnels and the like.
  • the principal object of the present invention is to overcome or at least substantially reduce some at least of the above mentioned drawbacks associated with known fluid flow sensing systems.
  • It is an object of the present invention also to provide a single-phase flow meter which is capable of (1) providing sensitivity over the range 200 to 20,000 barrels/day and (2) operating up to temperatures of 190°C in the harsh downhole environment.
  • It is another object of the present invention also to provide an improved fluid flow sensor which can measure fluid flow in water injection wells and oil and gas production wells by the ability to place non-invasive sensors in either the production tubing above or below packers or in between the perforations in a cased well or indeed in the open well.
  • it is another object of the present invention also to provide a novel low cost flow sensor which can be installed in wells during completion operations so that water, and oil and gas recovery may be monitored on-line so that control of the wells and planning of new wells may be exercised to maximise oil or gas production.
  • the present invention resides in the concept of taking advantage of a fluid flow sensor with an enhanced detection capability which can respond to the mechanical perturbations of the sensor itself arising from the impingement of turbulent fluid flow on the sensor.
  • a fluid flow sensing apparatus for measuring a fluid flow rate
  • the apparatus comprising: fluid flow sensing means for sensing perturbations associated with the apparatus, the perturbations being produced by the broadband energy in the turbulent fluid flow impinging on said apparatus, means for deriving a signal response representative of the sensed perturbations and processing means for processing the derived signal response to provide measurement of the fluid flow rate at a predetermined location.
  • the fluid flow sensing means advantageously comprises a sensor device having a body member (a cylindrical member for example) with an aperture, the sensor device being so formed to permit the passage of the fluid flow through the aperture and/or around the outside surface of the body member.
  • the sensor of the invention can be conveniently mounted either directly into a production pipe sub, or attached to a extension thereof/the so called stinger projecting down beyond the packers into the production zone. Further, the sensor can be installed after the casing is completed and together with the production tubing installations. The sensor can be also installed between packers or control valves in sectioned intervals of the production zone.
  • the senor of the invention can be pre-installed in production tubing to determine fluid flow rates for the lifetime of the production tubing, thereby dispensing with the need for expensive logging intervention associated with spinner-type flow meters.
  • the sensor of the invention finds utility for many applications such as in pipelines and tunnels.
  • a fibre optic sensing system incorporating a fluid flow sensing apparatus of the kind as described hereinabove.
  • the method of deployment conveniently uses optical cables or standard control tube techniques which are familiar to oil companies for the deployment of fibre optic temperature and pressure gauges, and furthermore, the optical architecture is such that the sensors may be sited at different levels within the production well.
  • the fibre optic sensor conveniently comprises a fibre optic sensing coil embedded into a material of relatively low bulk modulus which in turn is encased in a corrosion resistant pressure housing such as stainless steel or titanium.
  • time multiplex means and/or optical frequency multiplex means can be advantageously provided to multiplex a number of fibre optic sensors onto one optical fibre, enabling fluid flow gradients to be measured along an array of such sensors over spatial distances up to and typically in excess of 10 Km.
  • the fibre optic sensor is conveniently connected to a fibre cable which is used to carry laser power to the sensor.
  • the resulting reflected phase modulated light signals from the sensor are in turn carried to an opto-electronic processor sited in a habitable workspace, using an architecture and sensing technique similar to that disclosed in GB2126820 and US4653916 for example, and well-removed from the borehole environment or other harsh environment.
  • an improved fluid flow sensing system incorporating a novel mechanical filter in the design of the sensing means such that the interference effects attributed to the broadband excitation of the entire support structure are removed directly.
  • the sensing means could be otherwise perturbed by the supporting structure and provide erroneous measurements of fluid flow.
  • a method of measuring a fluid flow rate comprising sensing perturbations associated with a fluid flow sensing apparatus or system of the kind as described hereinabove, said perturbations being produced by the broadband energy in the turbulent fluid flow impinging on said apparatus or system; deriving a signal response representative of the sensed perturbations; and processing the derived signal response to provide measurement of the fluid flow rate at a predetermined location.
  • the sensing step of the method can be carried out optically using a fibre optic sensing coil.
  • the generic method of optical sensing using time domain reflectometric interferometer techniques is well known to the skilled man in the art (see GB2126820 and US4653916 for example).
  • the heart of the present invention is directed to an apparatus and method for extracting turbulent flow energy from fluid and thereby sensing the mechanical perturbations of the sensor itself. It is, therefore, important in this invention to recognise that the actual sensor technology could be various and inclusive of electronic technology where high temperature/harsh environments are not such an issue, for example where there is a measurement of fluid flow in surface or buried pipes or tunnels.
  • the fluid flow sensing apparatus 1' comprises a cylindrical body member 1 with an aperture immersed in flow of fluid 2 such that the fluid flow passes through the aperture and/or around the outside surface of the body member 1 along a predetermined axis shown as 3.
  • the sensor device 1' is attached to springs 4 which allow the device 1' to be perturbed in a direction of this axis 3 by the energy contained in the broadband turbulent flow impinging on the device 1'.
  • the springs 4 are conveniently axial coil springs which, in combination with the mass of the device 1', enable the device 1' to vibrate at resonant frequency in the direction of the axis 3 caused by the broadband energy in the frequency spectrum of the forces in the turbulent fluid flow impinging on the device 1'.
  • the device 1' senses the resulting mechanical perturbations at the resonant frequency or off the resonant frequency such that a measurement of fluid flow rate is made at a particular location.
  • the springs 4 are anchored by mounts 5 to a stationary part such as pipework or concrete anchorage point 6.
  • the device is thus free to resonate due to the broadband excitation of the resonant structure as hereinafter described.
  • a distributed sensor 7 mounted within the body of the device responds to the perturbations or trembling of the device due to the turbulent flow of the fluid and a cable 8 carrying signals from the sensor passes through the hollow springs 4 to the surface via high pressure control tube 9, to the equipment 10 at the surface.
  • the hollow springs 4 therefore provide a dual function insofar as (1) they are used to accommodate the signal carrying means (cable 8) to permit transmission of the signal response from the device 1' to the processor 10, and (2) they are used to provide a resonance condition of the device 1' in use.
  • the device 1' may be attached to a pipework or concrete anchorage point 6 by means of more rigid methods than the spring 4 shown in figure 1 and this would modify and raise the resonant frequency condition of the device 1'.
  • methods other than the use of control tube may be used to deploy the signal cables and will be familiar to those skilled in the art of connecting sensors downhole in harsh environments.
  • the output of sensor 7 representing the perturbations of the device are detected by the equipment 10 and the frequency power spectral density is computed, from which flow rate may be interpreted from a priori calibrations.
  • the sensor technology may comprise piezo-electric, piezo-magnetic, piezo-resistive, electro-strictive, electro-mechanical, micro-machined and optical technology as described hereinafter by way of examples.
  • a skilled man in the art of vibration analysis would further recognise that there may be other technologies suited to this particular sensing application but which would not depart from the spirit and scope of the present invention.
  • Each may have its merits and be able to pass signals via a cable 8 through the springs 4 and control tube 9 or other suitable cabling to a surface unit away from the harsh environment.
  • fibre optic technology is preferably used which is highly sensitive and suited to applications in high temperature oil wells
  • a housing is preferably provided to house a coil shaped fibre optic sensor 7 within the hollow cylindrically shaped device which relieves the high hydrostatic pressure environment from the fibre.
  • the control tube 9 relieves the high pressure on the cable 8 en route to the surface equipment 10 which comprises laser source and opto-electronic processing.
  • the cylindrical device 1' made of hard material with high elastic modulus contains a cylindrical cavity 12 into which is wound a fibre optic sensing coil 13 embedded in an encapsulate 14 of relatively low elastic modulus.
  • Time domain reflectometric interferometer techniques are advantageously employed, these being well known to those skilled in the art.
  • the fibre optic sensing coil 13 forms one arm of the interferometric system and discontinuities 15a realise the partial reflectors within the fibre coil 13.
  • a realisation of the discontinuity is the partial reflection obtained using optical 2x2 couplers 15b.
  • the fibre optic cables 8, 16 and 18 are deployed in control tubing 4,9 and the coupler 15b is also deployed in a pressure resistant housing 21.
  • the fibre optic components 8,15b, 16 and 18 from the harsh environments or indeed for any other of the described embodiments of the invention where a measurement of fluid flow is to be made.
  • the embodiment of Figure 2 could be also modified to accommodate a plurality of flow sensors, the sensors being multiplexed onto the same optical cable 11 deploying a plurality of the fibre optic sensing coils 13 housed in a plurality of the devices 1', inter-connected with the fibre cable 11 using an optical architecture familiar to those skilled in the art of multiplexed optical fibre sensing using either time division or wave division multiplexing techniques or both.
  • an optical architecture familiar to those skilled in the art of multiplexed optical fibre sensing using either time division or wave division multiplexing techniques or both.
  • Figure 3 shows another embodiment of the present invention for particular application in a production pipe. More particularly, as shown in the Figure, the fluid flow 2 is measured in production tubing suitably bellowed 22 to accommodate the cylindrical device 1 and the springs 4. This bellowing feature facilitates the passage of drill pipe, coiled tubing or logging tools down through the flow sensor as is often the requirement but clearly the need to deploy a mechanical spinner type flow meter is obviated by the deployment of the sensor of the present invention.
  • the design also allows multiplexing of fibre optic sensors onto a fibre optic cable (see Figure 2) for purposes of making temperature and pressure measurements for example.
  • the senor of the invention could also be configured in such a way as to be installed on the outside of the production tube. This would be of practical benefit in those situations where fluids flow on the outside of the production tube. It would also be apparent to anyone skilled in the art that the sensor of the invention could also be configured in such a way as to be installed on the inside of a section of borehole liner or casing. Such a configuration would be of practical benefit in those situations where no production tubing was present in a cased hole.
  • FIG. 4 there is shown another embodiment of the invention where the fluid flow is measured in an open well 25 at the producing zone.
  • the device 1 and springs 4 are mounted 5 onto an extension of the production tube onto the so called Stinger 28, a steel member which is routinely pushed into open wells for the purposes of instrumentation and fluid injection.
  • Figure 5 shows another embodiment of the invention for measuring fluid flow 2 at the production zone and is similar to the stinger mounted figure 4 embodiment described for the open well excepting that the production zone is cased 23 with perforated or slotted liner 29 which may or may not be cemented 24 into the rock 25.
  • the sensor measures fluid flow 2 which is the accumulation of all flows 2(a) upstream of the sensor from production of fluids through permeable rock 27 and perforations 29.
  • Figure 5 uses the same reference numerals as were used to designate same/like parts in the description of figures 1 to 4.
  • Figure 6 shows another embodiment of the present invention for measuring fluid flow at the production zone and is similar to the stinger mounted figures 4 and 5 embodiments except that a plurality of sensors is installed.
  • three sensors 7(a), 7(b), 7(c) are shown to be mounted at three separate positions of the production zone in between perforations 29(a)', 29(a), 29(b), 29(c).
  • sensor 7(c) measures the accumulation of all flow 2(c) from Total Depth (TD)
  • sensor 7(b) measures the accumulation of all flow 2(c) and 2(b) from Total Depth (TD)
  • sensor 7(a) measures the accumulation of all flow 2(c), 2(b) and 2(a) from Total Depth (TD).
  • this embodiment can be modified to include any number of sensors within the production zone, and thus facilitate the monitoring of fluid production along the entire production zone. While the sensors are conveniently mounted in a series-arrangement, it is possible that the sensors are alternatively mounted in a parallel arrangement within the production zone.
  • the sensors can be conveniently connected in series on a single fibre by use of optical fibre splice boxes 26 to accommodate any spacing requirement of the sensors between perforations.
  • Splice box 30 is used to provide connectivity to other fibre optic sensors if required.
  • Figure 6 uses the same reference numbers as were used to designate same/like parts in the description of figures 1 to 5.
  • Figure 7 shows yet another embodiment of the invention for measuring fluid flow 2 using stinger mounted sensors similar to the plurality of sensors embodiment for measurement of differential flow in the production zone as previously described in relation to Figure 6.
  • the fluid flow is reversed and the plurality of sensors is set up for monitoring the differential flow of high pressure fluid (for example water) injected into the permeable rock strata 27 via perforations 29.
  • high pressure fluid for example water
  • the three sensors are used to measure water flow into the strata as follows.
  • Sensor 7(c) monitors the flow into level 32(c), sensor 7(b) monitors flow into 32(c) and 32(b) and sensor 7(a) monitors flow into 32(c), 32(b) and 32(a).
  • this embodiment can be modified to include any number of sensors.
  • the flow of water into each of the permeable zones is monitored and may be used advantageously for well control and planning purposes.
  • a connection with other fibre optic downhole gauges may be made at splice box 30.
  • Figure 7 uses the same reference numerals as were used to designate same/like parts in the description of Figure 6.
  • Figure 8 shows another embodiment of the invention applied to monitoring the fluid flow from different perforated production zones 29 which arise in multi-lateral configurations of the downhole completions.
  • the plurality of sensors monitor differential flow in a similar manner to that previously described for a single well (see Figure 6).
  • Sensor 7(c) measures the accumulation of flow 2(c) from Total Depth (TD).
  • Sensor 7(b) measures the accumulation of flow 2(c) from TD and 2(e) produced from the lateral casing 33 at perforations 29(c) and 29(e) and sensor 7(a) measures the accumulation of all flow 2(c), 2(d) and 2(e) produced from lateral casing 33 and 33(e).
  • this embodiment may be modified to include any number of sensors within the production zone containing any number of lateral sections, and again the measurements of differential flow may be combined with other fibre optic gauges either spliced 30 onto the same fibre or deployed on separate control tubes containing fibre optic Distributed Temperature Sensors.
  • Figure 8 uses the same reference numerals as were used to designate same/like parts in the description of figures 6 and 7.
  • the senor provides an output in dependence upon the degree of the sensed perturbations, this being dependent upon the amount of turbulent fluid flow impinging on the sensor.
  • Circuitry associated with the sensor can be used to (1) resolve the sensor output into a signal representative of the sensed perturbations and (2) process the signal to provide measurement of the fluid flow at a predetermined location. It is equally possible to use computer software for controlling the operation of the fluid flow sensor such as to permit the signal response of the sensor to be derived and/or processed.
  • the intention is to identify some parameter such that the measurand changes monotonically (but not necessarily linearly) with flow speed, the range of interest being from 0.05 m/sec to 1.5 m/sec.
  • the size of the pipe and the viscosity and speed of the fluid are such that the Reynolds Number is always greater than about 2000, then the velocity field in the pipe will be varying in both time and space according to the magnitude of the Reynolds number and the intensity of the associated turbulence.
  • the important feature of this flow is that it is time varying and its broad spectrum defines the turbulent energy across a range of frequencies.
  • the frequency response curve will show a clearly defined peak at that resonant frequency.
  • the amplitude of the peak above the background excitation depends on the extent to which the structure is damped, being inversely proportional to the damping factor, and proportional to the so-called Q factor.
  • the advantage of using a structure with a reasonably high Q factor, say about 10, is that the amplitude at the resonant frequency is magnified by that amount, and is therefore easy to detect above any other noise which may be present in the system. It is observed that this peak amplitude generally increases with increasing flow rate, and it is this property of the system which makes it useful as a flow sensor.
  • the measurand may be either displacement, velocity, or acceleration. This may be measured with any sensing mechanism which responds in a useful way to the measurand, such as a bundle or coil of optical fibre, as embodied in the present invention.
  • a suitable resonant structure is shown in Figure 1, and takes the form of a housing 7 mounted on springs 4 containing an accelerometer or some element, such as a coil of optical fibre, sensitive to acceleration.
  • an accelerometer or some element such as a coil of optical fibre, sensitive to acceleration.
  • the effective mass of the sensor increases as its motion accelerates the fluid around it; for a cylinder this so-called added mass is equal to the mass of the fluid displaced by the cylinder, but will be different for other geometries.
  • the effect of immersion is to slightly lower the resonant frequency.
  • the distribution of turbulent energy in the frequency domain depends on the friction due to the pipe, which is generally taken to be constant if the pipe is very rough and the Reynolds number greater than about 2000.
  • the friction is a weak function of Reynolds number, and hence velocity. It is assumed that the geometry of the installation will remain constant, although it is possible that temperature, and hence viscosity and Reynolds number, may vary. Since it is always possible to measure temperature, the appropriate corrections to the friction factor can be made.
  • the variation of the root mean square (rms) pressure on the body generally consists of straight lines with a characteristic "knee" as shown in Figure 9.
  • These curves are calculated for four frequencies from 10Hz to 80Hz, where the x-axis represents the speed of the fluid flow, and the y-axis is expressed in log(pressure/Pa). It can be seen that the energy available for exciting the structure falls slowly with decreasing flow rate until a critical speed is reached. At this point the energy falls rapidly, and the effectiveness of the device as a flow speed sensor declines.
  • viscous corner frequency which is a function of friction, viscosity and speed, defines the location of the "knee”, and it is convenient to ensure that the resonant frequency of the structure is below this corner frequency, which may typically be around 100 Hz for flow rates of the order of 0.1 m/sec.
  • Figure 10 shows a representative spectrum of mean square pressure over a limited frequency range for flow speeds from 0.05 m/sec to 0.4 m/sec.
  • the resonant structure is taken to be a linear, 2nd order mechanical system whose response after excitation by the forces represented by the spectrum in Figure 10, has the appearance shown in Figure 11.
  • a range of flow speeds from 0.1 m/sec to 1.6 m/sec is represented, and the resonant frequency is 20 Hz. If just the maximum amplitude of the response is measured, the predicted result is as shown in Figure 12 for a range of resonant frequencies from 10 Hz to 80 Hz.
  • Figure 13 shows experimental data for which measurements were taken off resonance at 30 Hz.
  • the resonant frequency of the system was 36 Hz.
  • the power spectral density (psd) has been averaged over a 1 Hz band and plotted against log (flow speed) to give a usefully linear curve, showing that the relationship between the turbulence induced vibration and flow speed is approximately a power law.
  • Figure 14 shows a set of similar results taken on -resonance at 36 Hz for low flow speeds from 0.05 m/sec to 0.6 m/sec.
  • a source of mechanical interference is the vibration of the entire support structure holding the sensor thereby causing the sensor to vibrate additionally to the impingement of fluid flow. Under these circumstances there may be other resonances superimposed on the response of the resonator.
  • the stinger In down-hole production well applications, there is the possible requirement for the sensor to operate in an environment where mechanical vibration is transmitted through the production tubing or extension thereof (the so-called stinger).
  • This mechanical vibration emanates either from the production rig floor or from down-hole mechanical installations such as electric submersible pumps or down-hole apparatus of any description, and may cause mechanical interference such that the entire support structure holding the sensors may vibrate, thereby interfering with the accuracy of the flow measurement causing the sensor to vibrate additionally to the impingement of fluid flow. This will interfere with the accuracy or sensitivity of both broadband and narrowband measurement techniques.
  • One known solution by way of example is to rigidly mount reference sensors or accelerometers in close proximity to the flow sensors, such that the motion of the structure is measured and adaptive processing methods may be deployed to reduce the level of broadband or normal interference. This is a method that might be described as common practice by those skilled in the art of noise and vibration cancellation.
  • Another known solution for the avoidance of the interfering tonal vibrations which emanates from down-hole motors and pumps at frequencies related to rotational speed is to choose the resonant frequency of the sensor such that it avoids these tonal frequencies facilitating an accurate measurement of flow by the on resonance method.
  • FIG 15 there is shown yet another fluid sensing apparatus 1, 1a embodying the present invention and it is noted that this Figure differs from that already described in Figure 1 by the addition of dual sensor body members 1a.
  • the dual sensor devices are attached to springs 4 and 4a which allow the devices 1, 1a to be perturbed in a direction of axis shown as 3.
  • the springs 4 and 4a are conveniently axial coil-springs which in combination with the masses of devices 1 and 1a enable the devices 1, 1a to resonate in the direction of axis 3 caused by the broadband energy in the frequency spectrum of the forces in the turbulent fluid flow impinging on the devices 1, 1a.
  • the purpose of the double sensor devices 1, 1a is to generate two principal resonances in the axis direction 3.
  • the lower frequency resonance represents the two devices moving axially in phase together by the combination of the springs 4, 4a in resonance with the mass of sensor devices 1, 1a. Such resonances may be excited by both turbulent flow and the axial vibration of the stinger.
  • the higher principal axial resonance is the result of the two sensor devices 1, 1a moving in opposite directions out of phase with each other by, again, the combination of the springs 4, 4a in resonance with the mass of sensor device 1 and sensor device 1a.
  • Such a higher resonance can be generated by turbulent flow, as before, and if the mounts 5 are separated by a distance small compared with the wavelengths of the interfering vibration, it is not excited by the axial vibration of the mounts.
  • the method of measuring turbulent flow is thus to measure the magnitude of the higher frequency out of phase resonance which is unaffected by axial vibration of the mounts 5.
  • the resonant vibration of the sensors is due to the extraction of energy from the broadband energy in the turbulent flow, at both higher and lower resonant frequencies, the resonant excitation of the sensors at the lower frequency is due to noise vibration of the energy from the broadband energy in the frequency spectrum of the interfering forces impinging on the mounts 5 only.
  • the double sensor behaves as a mechanical filter whereby the measurement of the magnitude of the higher resonant frequency will only be due to the turbulent flow excitation and vibration interference is separated in frequency.
  • FIG 16 A simple 4 degrees of freedom mechanical model is described in Figure 16 to represent the axial response of the dual sensor embodiment of Figure 15.
  • the Figure 15 embodiment is based on the principle of mounting the identical two sensors at a common point, thereby reducing the effect of transmission of vibration at the mount.
  • the mass 1 represents the mass of the supporting structure in Figure 15.
  • the structure 6 is considered to be high mass and all spring mounts 5 are considered to be at one common node point, that is high vibration coherence between the two mounts.
  • the masses 2 and 3 represent sensors 7d of Figure 15.
  • the stiffness K2 and K4 represent the spring coiled tubes linking the sensors 7d in Figure 15 with an attached spring stiffness K1 at the centre tap joining this point to the common node point. In practice, this stiffness is preferentially considered to be zero in the calculations, inferring no connection to the mid-point of K2, K4 which may thus be realised as one spring; shown as 4a in Figure 15.
  • the stiffness K3 and K4 are the coil springs 4 in Figure 15. Running a computer model with the following parameters has been done as a worked example:
  • the lower curve in Figure 17 shows the acceleration at the common node point on Mass 1 (i.e. mounts 5 in Figure 15) and is due to be induced excitation of the structure 6 by remote interfering sources.
  • the upper curve in Figure 17 shows the acceleration of Mass 2 and Mass 3 due to flow excitation and also from interfering vibration excited through the mounts. It can be seen from the plots that the out-of-phase resonance occurs at the higher resonant frequency (approx. 34Hz in this example) and that the excitation of the structure 6 (Mass 1) does not excite the out-of-phase resonance but does excite the in phase resonance (at approx. 17Hz in this example). It is thus to be appreciated that the measurement of excitation at the higher resonant frequency represents an interference free measurement of fluid flow.
  • the embodiments are in all respects exemplary and that modifications and variations are possible without departure from the spirit and scope of the invention.
  • the scope of the sensing arrangement could possibly be improved, if desired, by provision of additional sensors in the production zone where the fluid flow rate is to be measured.
  • the sensing arrangement could be easily modified to combine the intelligent use of distributed flow rate measurements with intelligent down-hole completions so that control valves may be activated to shut down laterals or production zones thus maximising the production of the wanted fluid, for example by shutting off water.
  • the body member of the sensor is preferably a cylindrical member with an aperture
  • the body member could alternatively be of a different shape and size without an aperture and the same or similar technical effect of the invention would be obtained.
  • the actual sensor technology for use in the present invention could be various and could even be inclusive of electronic technology where high temperature/harsh environments are not such an issue to the fluid flow rate measurements.

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  • General Physics & Mathematics (AREA)
  • Electromagnetism (AREA)
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  • Measuring Volume Flow (AREA)
EP20020006630 2001-04-06 2002-03-25 Accéléromètre à fibres optiques pour mesurer un débit de fluide Expired - Lifetime EP1248082B1 (fr)

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Application Number Priority Date Filing Date Title
EP20020006630 EP1248082B1 (fr) 2001-04-06 2002-03-25 Accéléromètre à fibres optiques pour mesurer un débit de fluide

Applications Claiming Priority (7)

Application Number Priority Date Filing Date Title
GB0108739A GB0108739D0 (en) 2001-04-06 2001-04-06 An apparatus and method of sensing fluid flow
EP01303278 2001-04-06
GB0108739 2001-04-06
EP01303278 2001-04-06
GB0200139A GB2375177B (en) 2001-04-06 2002-01-04 An apparatus and method of sensing fluid flow
GB0200139 2002-01-04
EP20020006630 EP1248082B1 (fr) 2001-04-06 2002-03-25 Accéléromètre à fibres optiques pour mesurer un débit de fluide

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EP1248082A1 true EP1248082A1 (fr) 2002-10-09
EP1248082B1 EP1248082B1 (fr) 2010-09-01

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Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US7997340B2 (en) * 2002-11-05 2011-08-16 Weatherford/Lamb, Inc. Permanent downhole deployment of optical sensors

Citations (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5155548A (en) * 1990-05-22 1992-10-13 Litton Systems, Inc. Passive fiber optic sensor with omnidirectional acoustic sensor and accelerometer
EP0519754A2 (fr) * 1991-06-20 1992-12-23 Exxon Research And Engineering Company Débitmètre non-intrusif pour la composante liquide d'un écoulement biphasique, basé sur le son transmis par des milieux solides ou fluides
WO2000000793A1 (fr) * 1998-06-26 2000-01-06 Cidra Corporation Mesure de parametre de fluide dans des canalisations a l'aide de pressions acoustiques
US6072567A (en) * 1997-02-12 2000-06-06 Cidra Corporation Vertical seismic profiling system having vertical seismic profiling optical signal processing equipment and fiber Bragg grafting optical sensors

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US5155548A (en) * 1990-05-22 1992-10-13 Litton Systems, Inc. Passive fiber optic sensor with omnidirectional acoustic sensor and accelerometer
EP0519754A2 (fr) * 1991-06-20 1992-12-23 Exxon Research And Engineering Company Débitmètre non-intrusif pour la composante liquide d'un écoulement biphasique, basé sur le son transmis par des milieux solides ou fluides
US6072567A (en) * 1997-02-12 2000-06-06 Cidra Corporation Vertical seismic profiling system having vertical seismic profiling optical signal processing equipment and fiber Bragg grafting optical sensors
WO2000000793A1 (fr) * 1998-06-26 2000-01-06 Cidra Corporation Mesure de parametre de fluide dans des canalisations a l'aide de pressions acoustiques

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US7997340B2 (en) * 2002-11-05 2011-08-16 Weatherford/Lamb, Inc. Permanent downhole deployment of optical sensors

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